KR102131467B1 - Aqueous alkanolamine solution and process for the removal of h2s from gaseous mixtures - Google Patents

Abstract

The present invention relates to an aqueous alkanolamine solution for removing hydrogen sulfide from a gas mixture. The aqueous alkanolamine solution comprises (i) an amino compound of formula (I): (ii) an acid or acid-forming material having a pKa of 8 or greater; Optionally (iii) another amino compound; And optionally (iv) a physical solvent:
[Formula I]
R ¹ R ² NCH ₂ CH(OH)CH ₂ OH
In the above formula,
R ¹ and R ² independently represent a lower alkyl group of 1 to 3 carbon atoms.
The invention also relates to a method for removing acid gas from a gas mixture, preferably hydrogen sulfide, comprising contacting the gas mixture with an aqueous alkanolamine solution, preferably at the temperature of the aqueous alkanolamine solution. Is more than 140°F. Examples of gas mixtures include natural gas, synthetic gas, tail gas and refinery gas.

Description

Method for removing hydrogen sulfide from aqueous alkanolamine solution and gas mixture {AQUEOUS ALKANOLAMINE SOLUTION AND PROCESS FOR THE REMOVAL OF H2S FROM GASEOUS MIXTURES}

The present invention is an aqueous solution of an acid or acid-forming substance and a composition comprising an alkanolamine, preferably 3-(dimethylamino)-1,2-propanediol, and an acid gas from a gas mixture, such as CO ₂ , It relates to a method of using the aqueous composition for removing COS and H ₂ S, preferably for removing H ₂ S from a gas mixture under conditions where the aqueous solution is hot.

Natural gas storage, fluid streams derived from petroleum or coal often have significant amounts of acid gas, such as carbon dioxide (CO ₂ ), hydrogen sulfide (H ₂ S), sulfur dioxide (SO ₂ ), carbon disulfide (CS ₂ ). , Hydrogen cyanide (HCN), carbonyl sulfide (COS), or mercaptan. The fluid stream may be a gas such as natural gas, refinery gas, hydrocarbon gas from shale pyrolysis, synthetic gas, or the like, or a liquid such as liquefied petroleum gas (LPG) and natural gas liquid (NGL), or mixtures thereof.

Various compositions and processes for removing acid gases are known and described in the literature. It is well known to treat gas mixtures with aqueous amine solutions to remove these acid gases. Typically, the aqueous amine solution is contacted with a gas mixture comprising acidic gas refluxing at low temperature and high pressure in the absorber tower. Aqueous amine solutions are typically alkanolamines such as triethanolamine (TEA), methyldiethanolamine (MDEA), diethanolamine (DEA), monoethanolamine (MEA), diisopropanolamine (DIPA), or 2- (2-aminoethoxy)ethanol (sometimes referred to as diglycolamine or DGA). In some cases, the accelerator is combined with an alkanolamine such as piperazine and MDEA as disclosed in U.S. Patent Nos. 4,336,233, 4,997,630 and 6,337,059, all of which are incorporated herein by reference in their entirety. Used in combination. Alternatively, EP 0134948 discloses mixing an acid with a selective alkali material, such as MDEA, to provide enhanced acid gas removal. However, European Patent No. 0134948 teaches that only select classes of alkali materials mixed with acids are available in aqueous alkali solutions to provide increased acid gas removal.

Tertiary amines such as 3-dimethylamino-1,2-propanediol (DMAPD) have been found to be effective in removing CO ₂ from gas mixtures (see US Pat. No. 5,736,116). In addition, in certain processes, such as the Gibotol Process, tertiary amines have been shown to be effective in the removal of H ₂ S, but have been found to have reduced capacity at high temperatures (eg, “Organic Amines”). -Girbotol Process", Bottoms, RR, The Science of Petroleum, volume 3, Oxford University Press, 1938, pp 1810-1815).

While the compounds are effective, each of these has limitations that impair their universal use. In particular, aqueous alkanols for removing acid gases at commercially viable capacities when alkanolamines and/or aqueous solutions for removing H ₂ S from gas mixtures are used at high temperatures, for example above 140° F. Aqueous compositions comprising an amine solution may be preferred.

As described above, there is a need for aqueous alkanolamine solutions that are effective at removing hydrogen sulfide from a gas mixture and/or removing acid gases at high temperature operating temperatures, and methods of using the solutions.

The present invention is an aqueous alkanolamine solution composition, and a method of using the aqueous alkanolamine solution for removing acid gas, preferably as a method of removing hydrogen sulfide through contact with a gas mixture comprising the acid gas In this case, preferably, the temperature of the aqueous alkanolamine solution is 140°F or more, and the composition is based on the total weight of the aqueous alkanolamine solution,

(i) preferably from 0.1 to 75% by weight of the amino compound of formula (I):

(ii) preferably 0.1 to 25% by weight of an acid or acid-forming material, such as an organic or inorganic acid having a pKa of 8 or less, preferably 7 or less, more preferably 6 or less;

(iii) preferably from 0 to 75% by weight of one or more additional amino compounds different from the amino compound described in (i) above; And

(iv) optionally, preferably cyclotetramethylenesulfone, dienyl ether of polyethylene glycol, 1,3-dimethyl-3,4,5,6-tetrahydro-2(1H)-pyrimidinone, N- Physical solvent selected from formylmorpholine, N-acetylmorpholine, triethylene glycol monomethyl ether, and mixtures thereof

Includes:

[Formula I]

R ¹ R ² NCH ₂ CH(OH)CH ₂ OH

In the above formula,

R ¹ and R ² independently represent lower alkyl groups of 1 to 3 carbon atoms, for example methyl, ethyl, propyl and isopropyl groups, more preferred R ¹ and R ² groups include methyl and ethyl groups, in particular preferred amino compounds R ¹ and R ² are both methyl group of 3- (dimethylamino) -1,2-propanediol, and R ¹ and R ² are both ethyl group 3- (diethylamino) 1,2 -Propanediol;

The preferred additional amino compound comprises at least one tertiary amino group.

In one embodiment of the invention, the amino compound (i) is preferably 3-(dimethylamino)-1,2-propanediol or 3-(diethylamino)-1,2-propanediol.

In one embodiment of the invention, preferred acids (ii) are phosphoric acid, sulfuric acid, boric acid, formic acid, or hydrochloric acid.

In one embodiment of the present invention, the method further comprises a steam stripping step of the aqueous alkanolamine solution to form a hydrogen sulfide-rin aqueous alkanolamine solution that can be used in the contacting step.

1 shows a process flow diagram of an absorption process according to the invention.
2 is a plot of H ₂ S concentration to absorber circulation ratio in the purified gas mixture.

The aqueous solvent of the present invention is an aqueous amine solution comprising an alkanolamine compound and an acid or acid-forming material. Amino compounds useful in the aqueous alkanolamine solution of the present invention are compounds of formula I:

[Formula I]

R ¹ R ² NCH ₂ CH(OH)CH ₂ OH

In the above formula,

R ¹ and R ² independently represent lower alkyl groups of 1 to 3 carbon atoms, for example methyl, ethyl, propyl, and isopropyl groups. More preferred R ¹ and R ² groups include methyl and ethyl groups. A particularly preferred amino compounds R ¹ and R ² are both methyl group of 3- (dimethylamino) -1,2-propanediol, and R ¹ and R ² are both ethyl group 3- (diethylamino) -1, 2-propanediol.

The aqueous alkanolamine solution of the present invention is alkanes in an amount of 0.1% by weight or more, preferably 5% by weight or more, more preferably 10% by weight or more, and even more preferably 20% by weight or more based on the total weight of the aqueous solution. Contains amine. The aqueous alkanolamine solution of the present invention is in an amount of 75% by weight or less, preferably 65% by weight or less, more preferably 55% by weight or less, even more preferably 50% by weight or less based on the total weight of the aqueous solution. Alkanolamine.

Suitable acid or acid-forming materials that can be used in the present invention can be characterized as a strong acid comprising any organic or inorganic acid having a pKa of 8 or less, preferably 7 or less, more preferably 6 or less. Acids that can be used include phosphoric acid, boric acid, hydrochloric acid, sulfuric acid, boric acid, sulfurous acid, nitric acid, pyrophosphoric acid, ateluric acid, etc., which are preferred due to their low corrosion effect. Also suitable acids include organic acids such as acetic acid, formic acid, adipic acid, benzoic acid, n-butyric acid, chloroacetic acid, citric acid, glutaric acid, lactic acid, malonic acid, oxalic acid, o-phthalic acid, succinic acid, o-toluic acid, etc. do. In addition, acid-forming materials that can form acids upon contact with water can be used. Acids formed from these acid-forming materials useful in the present invention have a pKa of 8 or less, preferably 7 or less, more preferably 6 or less. A suitable acid-forming material is sulfur dioxide.

The aqueous alkanolamine solution of the present invention contains acids and/or acid-forming substances in an amount of at least 0.1% by weight, preferably at least 0.5% by weight, more preferably at least 1% by weight, based on the total weight of the aqueous solution. . The aqueous alkanolamine solution of the present invention is in an amount of 25% by weight or less, preferably 10% by weight or less, more preferably 5% by weight or less, even more preferably 2.5% by weight or less based on the total weight of the aqueous solution. Contains acids or acid-forming substances.

The aqueous absorbent composition of the present invention may optionally contain one or more additional amino compounds. Preferably, the additional amino compound is a second alkanolamine different or not described in Formula I hereinabove, such as tris(2-hydroxyethyl)amine (triethanolamine, TEA); Tris(2-hydroxypropyl)amine (triisopropanol); Tributanolamine; Bis(2-hydroxyethyl)methylamine (methyldiethanolamine, MDEA); 2-diethylaminoethanol (diethylethanolamine, DEEA); 2-dimethylaminoethanol (dimethylethanolamine, DMEA); 3-dimethylamino-1-propanol; 3-diethylamino-1-propanol; 2-diisopropylaminoethanol (DIEA); N,N-bis(2-hydroxypropyl)methylamine (methyldiisopropanolamine, MDIPA); N,N'-bis(2-hydroxyethyl)piperazine (dihydroxyethylpiperazine, DiHEP); Diethanolamine (DEA); 2-(tert-butylamino)ethanol; 2-(tert-butylaminoethoxy)ethanol; Or 2-amino-2-methylpropanol (AMP), 2-(2-amino-ethoxy)ethanol.

Preferred additional amino compounds include one or more tertiary amino groups.

Preferably, the additional amino compound has one or more sterically hindered amino groups. Aqueous absorbent compositions comprising 1-hydroxyethyl-4-pyridinylpiperazine compounds and amines having one or more sterically hindered amino groups are particularly suitable for the removal of H ₂ S.

When present, the amount of any amino compound in the aqueous alkanolamine solution can be at least 0.1% by weight, preferably at least 1% by weight, more preferably at least 5% by weight, based on the total weight of the aqueous alkanolamine solution. . When present, the amount of any amino compound in the aqueous alkanolamine solution can be 75% by weight or less, preferably 50% by weight or less, more preferably 25% by weight or less, based on the total weight of the aqueous alkanolamine solution. .

In order to remove H ₂ S from the gas mixture, the temperature of the aqueous alkanolamine solution in contact with the gas to be treated is at least 120°F, preferably at least 130°F, more preferably at least 140°F, even more preferred It is more than 150°F.

In addition to amino compounds and acids, aqueous alkanolamine solutions can include one or more other compounds used in fluid treatment according to well-known practices. Exemplary compounds that may optionally be provided include, but are not limited to, one or more of the following: anti-foaming agents, physical solvents including glycols and mono- and di-ethers or esters thereof, aliphatic acid amides, N-alkylated pyrroliates. Money, sulfone, sulfoxide, etc.; Antioxidants; Corrosion inhibitors; Film formers; Chelating agents, such as metals; pH adjusting agents, such as alkali compounds. The amount of any of these ingredients is not critical, but can be provided in an effective amount according to known practices.

In addition to the amino compounds, acids, and any one or more other compounds used in fluid treatment, aqueous alkanolamine solutions can include physical solvents. Solvents such as cyclotetramethylene sulfone (available under the trade name SULFOLANE), dimethyl ether of polyethylene glycol (available under the trade name SELEXOL from The Dow Chemical Company), and Triethylene glycol monomethyl ether (TGME or methoxytriglycol from The Dow Chemical Company), 1,3-dimethyl-3,4,5,6-tetrahydro-2(1H)-pyrimidinone, N -Formylmorpholine, N-acetylmorpholine, or mixtures thereof are preferred.

When present, the amount of physical solvent in the aqueous alkanolamine solution may be present in an amount of at least 1% by weight, preferably at least 5% by weight, more preferably at least 10% by weight based on the total weight of the aqueous alkanolamine solution. have. When present, the amount of physical solvent in the aqueous alkanolamine solution may be present in an amount of 75% by weight or less, preferably 65% by weight or less, more preferably 50% by weight or less based on the total weight of the solution.

The invention presented herein has great application in the petrochemical and energy industries. For example, the present invention relates to the treatment of fluid streams, gases, liquids, or mixtures in a refinery, treatment of sour gas, treatment of coal vapor gas, treatment of harmful stack emissions, treatment of landfill gas, and human safety. A series of novel devices for handling emissions can be used.

The fluid stream to be treated by the process of the present invention contains an acid gas mixture comprising H ₂ S, and optionally other gases such as CO ₂ , N ₂ , CH ₄ , C ₂ H ₆ , C ₃ H ₈ , H ₂ , CO, H ₂ O, COS, HCN, NH ₃ , O ₂ , mercaptan, and the like. Often the gas mixture is found in combustion gas, refinery gas, city gas, natural gas, synthetic gas, tail gas, water gas, propane, propylene, heavy hydrocarbon gas and the like. Aqueous alkanolamine solutions herein are low molecular weight liquids and gases from the gasification of air/steam or oxygen/steam thermal conversions of, for example, shale oil retort gas, coal, or heavy and heavy residues when the fluid stream is a gas mixture. Up to, or particularly effective in the sulfur plant tail gas purification operation.

The process of the present invention is preferably optionally one or more other acid gas impurities, such as CO ₂ , N ₂ , CH ₄ , C ₂ H ₆ , C ₃ H ₈ , H ₂ , CO, H ₂ O, COS, It is used to remove H ₂ S from a gas stream comprising H ₂ S in the presence of HCN, NH ₃ , O ₂ , and/or mercaptan. However, the invention is H ₂ or more of S and one or CO _2, SO _2, CS _2, HCN, COS, and / or mercaptan, H ₂ S and at least one CO _2, N _2, from a gas stream containing CH _4, C ₂ H ₆ , C ₃ H ₈ , H ₂ , CO, H ₂ O, COS, HCN, NH ₃ , O ₂ , and/or mercaptan.

The absorption step of the present invention generally involves contacting a fluid stream, preferably a gas mixture, with an aqueous alkanolamine solution in any suitable contact vessel, e.g., representative absorption processes of U.S. Patent Nos. 5,736,115 and 6,337,059. And all of the above patents are incorporated herein by reference. In this process, the fluid stream containing H ₂ S and optionally other impurities from the removal of CO ₂ and/or H ₂ S is removed in a conventional manner, such as a tower packed in a ring, or in a sieve or foam reactor, or The vessel can be used to make close contact with the aqueous alkanolamine solution.

In a typical manner of practicing the present invention, the absorption step is performed by feeding a fresh aqueous alkanolamine solution to the upper region of the tower while feeding the fluid stream to the lower portion of the absorption tower. The fluid stream, predominantly off H ₂ S, appears in the upper position of the tower (sometimes referred to as treated or purified gas), and the loaded aqueous alkanolamine solution containing absorbed H ₂ S is near the tower or at the bottom of the tower. Is left. Preferably, the inlet temperature of the absorber composition during the absorption step is 120°F to 210°F, more preferably 140°F to 200°F. Pressure can be extensive; The permissible pressure is 5 to 2,000 psi in the absorber, preferably 20 to 1,500 psi, most preferably 25 to 1,000 psi. Contacting occurs under conditions such that H ₂ S is preferably absorbed by the solution. Absorption conditions and devices minimize CO ₂ pickup by minimizing the residence time of the aqueous alkanolamine solution in the absorption apparatus while simultaneously maintaining the residence time of the fluid stream having the aqueous absorbent composition sufficiently to absorb the maximum amount of H ₂ S gas. It is designed for. Facing a fluid stream with a low partial pressure, such as a thermal conversion process, will require less aqueous alkanolamine solution than a fluid stream with a high partial pressure, such as shale oil retort gas, under the same absorption conditions.

A typical process for the H ₂ S removal phase of the process is based on gas mixtures containing H ₂ S and CO ₂ at temperatures above 120° F. and gas velocities above 0.3 ft/sec. (“active” or bubble tray surfaces). ) In a column containing multiple trays, absorbing H ₂ S countercurrent contact with the aqueous alkanolamine solution of the amino compound according to the working pressure of the gas, wherein the tray column comprises less than 20 contact trays. , For example, have 4 to 16 trays typically used.

After contacting the fluid stream with an aqueous alkanolamine solution saturated or partially saturated with H ₂ S, the solution can be at least partially regenerated and recycled back to the absorber. Regarding absorption, regeneration can occur in a single liquid phase. Regeneration or desorption of the acid gas from the aqueous alkanolamine solution can be carried out in the conventional manner of heating, expansion, stripping with an inert fluid, or a combination thereof, for example, reducing the pressure of the solution or absorbing H ₂ S The temperature is increased until the point where it flashes off, or the solution is passed from the upper part of the vessel into the vessel of a construct similar to that used in the absorption step, and an inert gas such as air or nitrogen, or preferably steam, is passed through the vessel Pass it upward. The temperature of the solution during the regeneration step should be 120°F to 210°F, preferably 140°F to 200°F, and the pressure of the solution during regeneration should be 0.5 psi to 100 psi, preferably 1 psi to 50 psi . After purifying at least a portion of the H ₂ S gas, the aqueous alkanolamine solution can be recycled back to the absorption vessel. Production absorbers can be added as needed.

In a preferred regeneration technique, the H ₂ S-rich aqueous alkanolamine solution is sent to a regenerator where the absorbed components are stripped by a stream produced by boiling the solution. In flash drums and strippers, the pressure is generally 1 psi to 50 psi, preferably 15 psi to 30 psi, and the temperature is typically 120°F to 340°F, preferably 170°F to 250°F. The stripper and flash temperatures will of course be 15 psi to 30 psi stripper pressures depending on the stripper pressure, and the temperature will be 170°F to 250°F during desorption. Heating the solution to be regenerated can be carried out very suitably by indirect heating with low pressure steam. However, it is also possible to use direct injection of steam. The resulting hydrogen sulfide-lean aqueous alkanolamine solution can be used for contact with a gas mixture containing H ₂ S.

Preferably the purge gas contains less than 10 ppm H ₂ S meeting some environmental regulations, more preferably less than 4 ppm H ₂ S meeting typical pipeline specifications.

A preferred embodiment of the invention involves carrying out the method of the invention either continuously or as a continuous process. However, the method can be carried out batchwise or semi-continuously. The choice of process type used should be determined by the conditions, equipment used, type and amount of gas stream, and other factors apparent to those skilled in the art based on the present application.

Example

Examples 1 to 12 are aqueous amine absorber solutions comprising 50 parts by weight of an alkanolamine, 50 parts by weight of deionized water, and optionally 1 or 2 parts by weight of an acid, based on the total weight of the aqueous amine absorber solution. A gas stream comprising a synthetic mixture containing 4.2% by volume of H ₂ S, 16% by volume of CO ₂ and 79.8% by volume of N ₂ was treated with a pilot scale absorber to remove H ₂ S and CO ₂ . For each aqueous amine absorber solution, the gas stream was treated at three different flow rates. The compositions, process parameters and residual H ₂ S and CO ₂ levels for Examples 1-12 are listed in Table 1. In Table 1,

"MDEA" is 98% methyldiethanolamine available from The Dow Chemical Company;

"DMAPD" is 98% 3-dimethylamino-1,2-propanediol available from AK Scientific;

“H ₃ PO ₄ ”is 85% o-phosphoric acid available from Fisher Scientific.

Aqueous amine absorber solution was introduced into the pilot scale absorbent through the feed line 5 on top of the gas-liquid countercurrent packaged-bed absorption column 2 (FIG. 1). The gas stream was introduced through the feed line 1 to the bottom of the column 2 at a gas flow rate of 10 L/min. The absorber pressure was adjusted to 238 psi. Purification gas (i.e., a reduced amount of H ₂ S and CO ₂ ) is discharged from the top of the absorption device 2 through line 3, and residual H ₂ S and CO ₂ levels are analyzed by gas chromatography (GC) It was measured by. Aqueous amine solution loaded with H ₂ S and CO ₂ was flowed through the bottom of the absorber and left through line (4).

The aqueous amine in line (4) was reduced in pressure by a level control valve (8), flowed through the line (7) into the heat exchanger (9) and heated with an aqueous loading solution. The hot abundance solution was passed through line 10 to the top of regenerator 12. The regenerator 12 was equipped with a random packing effective for desorption of H ₂ S and CO ₂ gases. The pressure of the regenerator was set to 17 psi. Gas was passed through line 13 to condenser 14, which was cooled and condensation of any residual water and amines occurred. Gas was put into the separator 15, and the condensed liquid was separated from the gas phase. The condensed aqueous solution was pumped through the pump 22 and sent to the top of the regenerator 12 via line 16. The gas remaining from condensation was removed via line 17 for final collection and/or disposal. The regenerated aqueous solution was flowed through regenerator 12 and a close-mounted boiler 18. After the electric heating device was mounted, the boiling device 18 was evaporated as part of the aqueous solution to dry off any residual gas. Water vapor was generated from the back-boiling device, mixed with the falling liquid, and then discharged through line 13 to enter the condensation step of the process and returned to regenerator 12. After the regenerated aqueous solution from the boiler device 18 is left through the line 19 and cooled in the heat exchanger 20, it is pumped through the pump 21 and turned to the absorption device 2 through the supply line 5 sent.

The flow rate for the aqueous amine absorber was measured by slowly downward adjustment until the amount of H ₂ S in the purified gas line (3) was dramatically increased.

The results for Examples 1-12 are presented graphically in the plots shown in FIG. 2. H ₂ S levels (ppmv) were plotted against amine flow rate (cc/min).

Claims (9)

(i) an amino compound of formula (I):
(ii) an acid which is phosphoric acid, boric acid, formic acid or hydrochloric acid, having a pKa of 6 or less; And
(iii) optionally one or more amino compounds different from (i) above
An aqueous alkanolamine solution for removing hydrogen sulfide from a gas mixture comprising:
[Formula I]
R ¹ R ² NCH ₂ CH(OH)CH ₂ OH
In the above formula,
R ¹ and R ² independently represent a methyl, ethyl, propyl or isopropyl group. According to claim 1,
(i) the amino compound is present in an amount of 0.1 to 75% by weight based on the total weight of the aqueous alkanolamine solution;
(ii) the acid is present in an amount of 0.1 to 25% by weight based on the total weight of the aqueous alkanolamine solution;
(iii) An aqueous alkanolamine solution, wherein the optional amino compound is present in an amount of 0 to 75% by weight based on the total weight of the aqueous alkanolamine solution. According to claim 1,
Aqueous alkanolamine solution in which amino compound (i) is 3-(dimethylamino)-1,2-propanediol or 3-(diethylamino)-1,2-propanediol. According to claim 1,
(iv) physical solvent
Aqueous alkanolamine solution further comprising a. The method of claim 4,
Physical solvent (iv) is cyclotetramethylene sulfone, dimethyl ether of polyethylene glycol, 1,3-dimethyl-3,4,5,6-tetrahydro-2(1H)-pyrimidinone, N-formylmorpholine , An aqueous alkanolamine solution selected from N-acetylmorpholine, triethylene glycol monomethyl ether, and mixtures thereof. A method for removing hydrogen sulfide from a gas mixture comprising hydrogen sulfide, comprising contacting the gas mixture with the aqueous alkanolamine solution according to claim 1. The method of claim 6,
Method in which the temperature of the aqueous alkanolamine solution is at least 140°F. The method of claim 6,
The method further comprising steam stripping the aqueous alkanolamine solution to form a hydrogen sulfide-lean aqueous alkanolamine solution that can be used in the contacting step. delete

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